This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of hydrocarbons, such as oil and gas, has been performed for numerous years. To produce these hydrocarbons, a wellbore is typically drilled in intervals to reach a subsurface formation. Often, a filter cake is formed during drilling. Filter cake is a concentrated layer of solids from the drilling fluid that forms on the borehole wall opposite a permeable formation. It forms a screen or barrier between the formation and the wellbore, making fluid flow between the two areas more difficult.
Lost Returns
In a drilling operation, it is often possible for the circulating drilling fluid pressure to exceed the formation strength. When drilling pressure exceeds the formation strength, the formation cracks, or fractures and the drilling fluid flows into the formation through the fracture. This phenomenon is called lost returns. Lost returns can be costly due to the loss of drilling fluid, which has to be replaced for the drilling operations to resume. Lost returns may also result in a potentially hazardous event, such as a kick. A kick is an influx of formation fluid into the wellbore, which may cause damage to equipment and/or injury to operators and may cause flaring.
Lost returns is a common worldwide drilling problem that has significant costs due to lost drilling fluids, lost time, potential wellbore influx, and induced wellbore instability. Losses through propagated fractures constitute the overwhelming majority of lost returns in the industry (as opposed to vugular losses or seepage losses). Fracture Closure Stress (FCS) practices or methods have been developed to combat losses by utilizing a rock mechanics approach. See Dupriest, Fred E., Fracture Closure Stress (FCS) and Lost Returns Practices, SPE/IADC 92192 (2005). FCS is based on the idea that integrity is built in a formation by increasing the width of a fracture. This may be achieved with multiple approaches as varied as traditional LCM (lost circulation material), cement, polymers, or adhesive solids. The process of building integrity includes: (1) isolating the fracture tip from the wellbore so pressure can be applied to widen the fracture to increase its closing stress, and (2) building a width to a level that achieves a stress exceeding the wellbore pressure required to drill ahead. Isolation of the tip from wellbore pressure occurs when the LCM and barite lose sufficient carrier fluid to become immobile.
One issue with these stress building operations, especially in NADF (non-aqueous drilling fluid), is that very high fluid loss is needed to form the immobile mass in the fracture faces. If fluid loss is inadequate, the solids remain mobile, pressure continues to be transmitted to grow the tip and it is not possible to build pressure within the fracture to increase closing stress. The movement of these particles prevents the formation of the immovable mass and sometimes results in the slurry flowing back into the wellbore, called flowback.
Flowback prevention is a well-known issue in well stimulation operations. Some common flowback prevention techniques include: the use of a resin-coated proppant (See, e.g. K. H. NIMERICK, et. al., Compatibility of Resin-Coated Proppants with Crosslinked Fracturing Fluids, In Proceedings Volume, pp. 245-250, 65th Annual SPE Tech Conf (New Orleans, La., Sep. 23-26 1990)); the use of thermoplastic films (P. D. NGUYEN, et. al, Thermoplastic Film Prevents Proppant Flowback, Oil Gas J, 94(6): 60-62, (1996)); the addition of an adhesive coated material to the proppant (U.S. Pat. No. 5,582,249); and addition of magnetized materials to the proppant (U.S. Pat. No. 6,116,342).
A NADF is an invert emulsion with a non-aqueous base fluid (NABF) as the continuous phase and an aqueous fluid as the dispersed phase. The emulsion is stabilized by using surfactants. In addition, NADF consists of barite as a typical weighting agent. Note, the term “barite” is used throughout the application, but the term should be read to include the element barium and include particulate and other forms in which the element may be found. Other materials such as hematite or ilmenite are also used for increasing the weight of NADF. Fluid loss control agents such as colloidal solids are present in NADF. To improve the hole cleaning ability of NADF, viscosifiers such as organophillic clays are also used.
Lost returns are often difficult to treat in NADF due to the very low fluid losses achieved with most NADF filter cakes and the inability to dehydrate the solids. While the native permeability of the formation might allow rapid leakoff of the FCS fluid, a tight NADF filter cake on the fracture face prevents this from occurring. Some embodiments of the present techniques include a method to increase the permeability of the filter cake prior to the FCS treatment. By increasing the permeability of the filter cake on the fracture faces, greater leakoff occurs and an immobile mass is deposited.
Differential Pressure Sticking
Differential pressure sticking (DPS) is a common worldwide drilling problem that results in significant increases in non-productive time and overall well cost. Additionally, a DPS event may result in abandonment of a drilling operation at a particular hole and force a sidetrack. To mitigate DPS events, operators often minimize the overbalance (by decreasing mud weight), minimize stationary time, minimize drilled length through low pressure formations, increase drill collar and drill string stabilization, and optimize fluid properties in attempts to minimize the risk of sticking. However, despite the best efforts of operators a DPS event may still occur.
A common practice to free differentially stuck pipe is to pump a chemical “spotting” fluid. The purpose of the fluid is to dissolve or break down the filter cake so the pipe can be freed. Multiple spotting fluid options are available. Water-based drilling fluids (WBM) have engendered numerous spotting fluids that have been used successfully in the field. These spotting fluids are typically composed of NADF (non-aqueous drilling fluid). Spotting fluids function by reducing the area of contact and may penetrate the filter cake and relieve pressure differential.
Often, operators may choose to use a NADF while drilling if the risk of a DPS event is high. This decreases the filter cake permeability and causes the pressure differential to develop more slowly upon embedment. Additionally, the filter cake is much slicker, thinner, and easier to shear—all factors that minimize the risk of a DPS event. While the use of a NADF may be sufficient to avoid DPS events, such events still occur. This is especially the case when the fluid incorporates bit-generated coarse solids that result in leaky and thick filter cakes exposed to unsupported drill collars. In the event of sticking when using a NADF, there are currently minimal available options to free a differentially stuck well tool or pipe.
Other related material may be found in at least International Patent App. WO 2005/047643 A1; International Patent App. WO 2005/012687 A1; and SPE/IADC Publication No. 92192.